A key petrophysical property in determining whether a formation will produce viable amounts of hydrocarbons is the water saturation, S.sub.w, of the formation. S.sub.w is defined as the percentage pore space of the formation that is filled with formation water and is related to other parameters of interest, such as the bulk-volume water (BVW), the bulk-volume hydrocarbon (BVH) and the porosity (PHI) of the formation as follows: EQU BVW=PHI*S.sub.W ; EQU BVH=PHI*(1-S.sub.W).
Obviously, if the formation's pore space is completely filled with water, that is if S.sub.W =100%, such a formation is of no interest for the purposes of an oil search. On the other hand, if the formation is at the minimum possible water saturation it will produce all hydrocarbons and no water. The minimum possible water saturation of a formation is known as irreducible water saturation, S.sub.WIRR.
The irreducible water saturation S.sub.WIRR is related to the average grain size of a formation. For example, shales and clays, due to their platy structure and small grain size have immense surface areas compared to the same volume of sand grains. The effect of this is to bind large quantities of water to their structure. Additionally, due to their fine grain size and the strong forces that hold the water in place, shales have essentially zero permeability and high porosity. Thus, shales decrease the porosity of the formation that is available to hold producible (free) fluids and increase the amount of water that is bound to the formation. Using the relationship above, the irreducible water saturation S.sub.WIRR allows one to compute the water bound to the formation, known as the bulk-volume irreducible water (BVI) of the formation, i.e., the percentage of the unit volume of the formation that is irreducible formation water, as follows: EQU BVI=PHI*S.sub.WIRR.
Given the critical importance of the water saturation as discussed above, many techniques have been proposed for determining its value for a given formation. The standard approach to obtaining a value for S.sub.W is through the Archie formation factor process. The formation factor F is defined as: EQU F=R.sub.o /R.sub.w =C.sub.w /C.sub.o,
where R.sub.o is the resistivity of a reservoir rock when fully saturated with aqueous electrolyte of resistivity R.sub.w, and C.sub.o and C.sub.w are corresponding conductivities. Further, given knowledge of porosity (PHI), which is the fraction of the total volume of a sample that is occupied by pores and voids; and resistivity (R.sub.t), i.e., the resistance of reservoir rock that is partially saturated to degree S.sub.w with electrolyte of resistance R.sub.o, via conventional logging techniques, Archie formation factor analysis provides the following empirical relationships which relate the porosity (PHI) to formation factor (F), and resistivity to saturation. The relationships are: ##EQU1##
In practice, the values of "a" (formation-factor coefficient), "m" (cementation exponent), and "n" (saturation exponent) vary with the type of formation and the nature of the hydrocarbon. However, in most cases an analyst will use the same relationship over large intervals, intervals that may include a variety of lithologies, pore types, and grain sizes. In such circumstances, it is often difficult to select the correct values of "a", "m", and "n". A selection of the correct values is of a significant concern since these parameters are used to relate porosity to formation factor F, and, in conjunction with resistivity, to saturation.
In an attempt to reduce the complexity of the above-mentioned relationships, it is has been observed that if "a" is a constant, it should equal to 1, since F must be equal to 1.0. in 100% porosity. Thus, the relationship between formation factor F and porosity reduces to: ##EQU2##
Further simplification of Eq. (1) is possible if the porosity PHI and the saturation S.sub.W are not treated as independent variables. While the assumption that porosity and saturation are independent has been useful for performing laboratory studies of geologic structures, as known to log analysts, this complexity of the model is not necessary for interpreting an actual resistivity log.
Considering the above, it has been proposed to eliminate porosity and saturation as independent variables and use only the bulk-volume water term (the product of porosity and saturation) to model the relationship between the conductivity of the fluids involved and the measured conductivity of the formation. This approach has the additional benefit of avoiding the need to independently estimate the numerical values for the exponents "m" and "n."
In an article by George R. Coates and J. L. Dumanoir, entitled "A New Approach to Improved Log-Derived Permeability," SPWLA, Fourteenth Annual Logging Symposium, p. 1, 1973, it was found that a common value, "w", could be adopted for both the saturation exponent, "n", and cementation exponent, "m". The proposed single exponent expression used to relate BVW, i.e., PHI*S.sub.w, to resistivity is: EQU (PHI*S.sub.w).sup.w =R.sub.w /R.sub.t
where:
w is the single exponent used to relate the BVW to R.sub.w /R.sub.t ; PA1 PHI is the total porosity of the rock; PA1 R.sub.w is the resistivity of the formation water; and PA1 R.sub.t is the true resistivity of the rock.
The proposed single exponent expression has not been widely used in the logging industry until recently because a log analyst could only assume a rock to be completely water filled in order to examine an apparent value for w. In other words, the single exponent equation could only be solved for w by assuming that PHI*S.sub.w =PHI. The porosity term was determinable via conventional logging instruments.
The results obtained by assuming a water filled condition were only valid in the water zones and resulted in an overestimation of w in the hydrocarbon zones of interest. It has long been desired to solve w for a hydrocarbon filled condition, i.e., PHI*S.sub.w =BVI, such that a valid result for w could be obtained for hydrocarbon zones of interest.
Additional complications in using Eq. (1) to obtain accurate values for the desired parameters arise from the fact that the resistivity measurements are affected by the presence of clay minerals in the formation. In order to compensate for these effects which may significantly reduce the accuracy of the measurements it is required to obtain an estimate of the clay minerals content of the formation. Such estimates are traditionally obtained using subjective, frequently complicated and inaccurate clay indicator methods.
With the advent of NMR logging, new options for determining w as well as other fluid flow properties of porous media have arisen. In an article by A. Timur, entitled "Pulsed Nuclear Magnetic Resonance Studies of Porosity, Movable Fluid, and Permeability of Sandstones," in the Journal of Petroleum Technology, June 1969, page 775, it was shown experimentally that NMR methods provide a rapid non-destructive determination of porosity, movable fluid, and permeability of rock formation.
It is known that when an assembly of magnetic moments, such as those of hydrogen nuclei, are exposed to a static magnetic field they tend to align along the direction of the magnetic field, resulting in bulk magnetization. The rate at which equilibrium is established in such bulk magnetization upon provision of a static magnetic field is characterized by the parameter T1, known as the spin-lattice relaxation time.
It has been observed that the mechanism which determines the value of T1 depends on molecular dynamics. In liquids, molecular dynamics are a function of molecular size and inter-molecular interactions. Therefore, water and different types of oil have different T1 values.
In the heterogeneous media, such as a porous solid which contains liquid in its pores, the dynamics of the molecules close to the solid surface are also significant and differ from the dynamics of the bulk liquid. It may thus be appreciated that the T1 parameter provides valuable information relating to well logging parameters.
There exist a number of techniques for disturbing the equilibrium of an assembly of magnetic moments, such as those of hydrogen nuclei, for T1 parameter measurements. Each of these techniques provides means for measuring T1 of a rock formation within a certain volume (called the "sensitive volume") which is determined mainly by the shape of the magnetic field surrounding the magnetic structure. The signal-to-noise ratio of the measurement is limited by the ratio of the sensitive volume to the uniformity of the magnetic field within said volume (maximum flux density minus minimum flux density), and increases in proportion to this ratio.
In any given NMR instrument configuration, the apparatus will respond only to nuclei residing within the sensitive volume. In the present invention and prior art instruments described herein, the boundaries of the sensitive volume are determined by radiation patterns of transmitting and receiving antennae as well as a combination of the detailed structure of the magnetic field with the receiver's frequency passband. The radio frequency that a given nucleus will respond to or emit when excited is proportional to the flux density of the magnetic field in which it is immersed. The proportionality factor depends upon the nuclear species. For hydrogen nuclei, that factor is 42.5759 MHz/Tesla. If the NMR receiver's passband extends from 1.30 MHz to 1.31 MHz, the instrument will be sensitive to hydrogen nuclei in regions of the magnetic field that have flux densities between 30.5 mT and 30.8 mT, providing the antenna radiation pattern allows receiving sufficient signal from that locations.
If it is desired to study nuclei located within a particular region, the magnetic field structure, antenna radiation pattern and receiver passband must all be adjusted to be sensitive to that and only that region. Since the signal-to-noise ratio of the resulting signal is proportional to (among other factors) the square root of the receiver passband width, it is important to minimize the variation of the magnetic field within the desired sensitive volume; smaller variations (better field uniformity) mean a better signal-to-noise ratio. Since the signal-to-noise ratio also increases with increasing frequency, the nominal magnetic field intensity within the volume is also very important. It is immaterial whether this nominal intensity is defined as the central value, average value or some other value within the range of values encompassed by the sensitive volume because only large differences in signal-to-noise ratio are significant.
One technique for measuring T1 of a rock formation is exemplified by what is known as the "Schlumberger Nuclear Magnetic Logging Tool." That tool is described by R. C. Herrick, S. H. Couturie, and D. L. Best in "An Improved Nuclear Magnetic Logging System and Its Application to Formation Evaluation," SPE8361 presented at the 54th Annual Fall Technical Conference and Exhibition of the Society of Petroleum Engineers of AIME, held in Las Vegas, Nev., Sep. 23-26, 1979, and also by R. J. S. Brown et al. in U.S. Pat. No. 3,213,357 entitled "Earth Formation and Fluid Material Investigation by Nuclear Magnetic Relaxation Rate Determination."
The Schlumberger Nuclear Magnetic Logging Tool measures the free precession of proton nuclear magnetic moments in the earth's magnetic field by applying a relatively strong DC polarizing field to the surrounding rock formation in order to align proton spins approximately perpendicularly to the earth's magnetic field. The polarizing field must be applied for a period roughly five times T1 (the spin-lattice relaxation time) for sufficient polarization (approximately two seconds). At the end of polarization, the field is turned off rapidly. Since the protons spins are unable to follow this sudden change, they are left aligned perpendicularly to the earth's magnetic field and precess about this field at the "Larmor Frequency" corresponding to the local earth's magnetic field (roughly from 1300 to 2600 Hz, depending on location).
The spin precession induces in a pick-up coil a sinusoidal signal whose amplitude is proportional to the density of protons present in the formation. The signal decays with a time contrast "T2" (transverse relaxation time) due to non-homogeneities in the local magnetic field over the sensing volume.
Improved NMR logging tools and methods for using these tools are described generally in U.S. Pat. Nos. 4,710,713; 4,717,876; 4,717,877; 4,717,878; 5,212,447 and 5,280,243 all of which are commonly owned by the assignee of the present invention.
The method of the present invention, described in greater detail below, uses the logging tools and techniques described in the above referenced patents to obtain previously unavailable data relating to the composition of a geologic structure. The measurements from the above described tools are used in combination with new and existing theoretical developments to obtain enhanced information regarding the petrophysical properties of geologic structures. In particular, a novel interpretation of standard and NMR measurements is used to obtain characteristics of the formation including its clay mineral content which may then be used to determine key petrophysical parameters such as the water saturation.